Wellbores are typically formed by drilling a borehole to a first pre-determined depth and then lining the borehole with a steel casing. Typically, a number of sections of casing of decreasing diameter are used. A first section of casing is lowered into the wellbore and hung from the surface after the well has been drilled to a first designated depth. Cement is then circulated in the annulus between the outer wall of the casing and the borehole. The well is then drilled to a second designated depth and a second section of casing having a smaller diameter is run into the well. This process is typically repeated with additional casing sections of decreasing diameter until the well has been drilled to the total required depth.
According to one solution, the second section may be sufficiently long to extend to a wellhead and be “hung off” in the wellhead at surface. Once “hung off”, the second casing section is then cemented in the same manner as the first section. In some instances engineers prefer this solution to maintain well integrity. However, in certain environments, such as for example, in deepwater environments, long casing is often too heavy to risk as a single deployment. Also, Equivalent Circulating Density (ECD) with a long string can be too high causing the potential for circulation loss zones. Also, the annulus between the drillstring and the casing during drilling is relatively narrow all the way between the drilling assembly downhole and the wellhead meaning that higher pressure is needed to pump the drilling fluid through the annulus back to surface. Such high pressures may be high enough to cause the drilling mud to be pumped into the formation being drilled and thus cause damage or even destruction to the reservoir.
According to an alternative solution, the second section is fixed at a depth such that the upper portion of the second section overlaps the lower portion of the first section of casing. In this example, the casing which does not extend to surface is referred to as a “liner”. The liner section is then fixed to the first casing section, such as by using a device called a liner hanger. The liner section is then cemented in the same manner as the first casing section. As well design becomes more challenging, due to longer step outs and deeper targets, and reservoirs become depleted, there are more reasons to design well construction with critical casing strings run as liners. Also, in most wells, the use of liners mitigates the high mud pressure problem associated with the use of the long casing because when the liners are used, the annulus is relatively narrow only within the liner and becomes wider within the casing above the liner.
After the well has been drilled, it may be necessary to connect the liner string back to the surface (or a point higher up in the well). In this case, a string of casing is sealingly connected to the top of the liner section and runs all the way back to surface so that the liner is “tied back” to the surface (or a point higher in the well between the surface and the liner hanger).
The area above the production zone of the well is typically sealed using packers inside the casing or liner and connected to the surface via smaller diameter production tubing. This provides a redundant barrier to leaks, and allows damaged sections to be replaced. Also, the smaller diameter of the production tubing increases the velocity of the oil and gas. The natural pressure of the subsurface reservoir may be high enough for the oil or gas to flow to the surface. When this is not sufficient, such as for older wells, installing smaller diameter tubing may help the production, but artificial lift methods, such as gas lift, may also be needed. The well needs to be configured to receive the artificial lift apparatus.
Known methods for sealingly connecting a tie-back string of casing into a downhole liner section typically involve the use of a tool known as a polished bore receptacle (PBR). The PBR is a separate tool which is screwed to the top of the liner section. The PBR has a smoothed cylindrical inner bore configured to receive the lower end of the tieback casing. The tieback casing is landed in the PBR to form a sealed connection between the tieback casing and the liner. The lower portion of the tieback casing is configured with seals on its outer diameter and these seals seal within the PBR.
FIG. 1 shows a known method of providing liner tieback connection in a wellbore 100 in which a second tube 10 is tied back to the surface using a first tube 12. The wellbore 100 is dined with a casing 102 which incrementally decreases in diameter as the depth increases. Tubing 104 for gas lift, with an internal gas lift valve 106, is provided within the casing 102. The second tube 10 has a diameter of 9⅝ in (244 mm) and extends upwards into the upper adjacent casing which has a diameter of 13⅜ in (340 mm). A PBR 14 is connected to the upper end of the second tube 10. A liner hanger 16 at an upper portion, and cement 108 at a lower portion, fix the second tube 10 within the wellbore 100. The first tube 12 is lowered and the lower end of the first tube 12 fits within the polished bore of the PBR 14. By itself, particularly in harsh environments, the PBR 14 may not be able to provide sufficient sealing and so a tie back packer 18 can be provided above the joint of the first and second tubes. The slidable sealing provided by the PBR 14 does not assist with supporting the first tube 12 in the wellbore 100 and so an anchor 20 may also be provided.
A major disadvantage of this known tieback connection is that the majority of the inside length of the PBR is exposed and is susceptible to damage as other downhole tools are run into the wellbore. A downhole tool being run through the PBR may impact the polished inside surface of the PBR on its way downhole. This can cause damage that reduces the sealing ability of the PBR. Also, drilling debris can degrade the PBR sealing surfaces. In addition, it is known that associated components, such as tie back stingers, seal stems and packers can leak, particularly in harsh environments. Furthermore, the PBR allows for thermal expansion and contraction of the tieback liner longitudinally, during which the liner seals can move up and down in the PBR. Over time this movement can cause the seals to wear and ultimately to fail. This is regarded to be one of the major limitations of a conventional PBR. A conventional seal stem relies on elastomeric seals to create the seal between the tie-back string and the liner within the PBR. Elastomeric seals are prone to damage during deployment and are inherently prone to wear over time and thus cannot be relied upon to last the life of well. In addition they will be worn due to relative movement when the well temperature changes during production and shut in cycles. Hence, elastomeric seals are no longer considered suitable for a well barrier in some areas. Still furthermore, the PBR is generally short (3-4 m) causing spacing out of the tieback string to be sometimes difficult to achieve successfully first time. In deep wells, especially subsea wellheads, this can have a substantial time and cost implication. It is usually not possible to lengthen the PBR due to the design of the liner hanger system. A PBR is prone to damage and a relatively minor score may compromise the seal. Furthermore, the use of elastomeric seals in the well barrier envelope is not allowed in certain places, e.g. in the Norwegian sector of the North Sea. For the above reasons, engineers sometimes prefer to run a long casing string.
The applicant has appreciated the need for an alternative means of connecting to a liner which eliminates the need for a PBR or which reduces the likelihood of damage to a PBR and provided such an alternative arrangement. This arrangement is described in WO2011/048426 A2 and illustrated in FIGS. 2 to 5 as an alternative prior art method of providing liner tieback connection in a wellbore 100. Like features are given like reference numerals to those of FIG. 1. A tieback profile device 30 is provided at the upper end of the second tube 10 such that it has a greater diameter than the diameter of the second tube 10. The device 30 includes a number of internal recesses 32 at its internal bore. A 13⅜ in (340 mm) by 11¾ in (298 mm) liner hanger 34 is connected to the top of the device 30 and this attaches to the casing at the inner surface of the wellbore 100. The liner hanger 34, device 30 and upper portion of the second tube 10 are all configured to cross over from 13⅜ in (340 mm) to an outer diameter of 9⅝ in (244 mm). FIGS. 3 to 5 illustrate the sequence for installing the first tube 12. The first tube 12 is lowered so that its lower end is within the device 30 and lower than the internal recesses 32 of the device 30 (FIG. 4). An expandable tool 40 is then run on the lower end of a string of drillpipe down through the bore of the first tube 12 until the tool 40 is aligned with the recesses 32 of the device 30. The tool 40 includes a depth latch arrangement 42 for positioning at the correct vertical depth. The tool 40 includes a pair of seals which are vertically spaced apart by a distance greater than the vertical distance between the upper and lower recesses. The seals are actuated to form a seal between the outer surface of the tool 40 and the inner surface of the first tube 12 to define a chamber between the seals. Water is pumped through the drillstring, into the bore of the tool 40 and through apertures of the tool 40 and into the chamber. When the water pressure is sufficient, the first tube 12 expands by elastic then plastic deformation into the recesses 32. This creates a mechanical fixing and metal to metal seal between the second tube 10 and the first tube 12 via the device 30. The first tube 12 is now tied back to the surface. The seals can then be de-activated and the drill pipe string and tool 40 removed from the wellbore 100.
The improved arrangement provides a number of advantages over a conventional PBR. The metal to metal seal has sufficient resistance to the thermally generated axial loads. There is therefore little or no movement and so no wear. Also, the need for elastomeric seals is eliminated, so the device has no elastomeric material to wear out or get damaged. Also, the internal diameter of the device is not a polished seal surface and so its performance is much less affected by damage. Also, higher burst and collapse loads can be achieved.
However, while this method eliminates the need to use a PBR connection, it has a major limitation in that for certain wells the annular space between the outer casing string ID and the liner string OD too small to fit the expandable tieback connection. In a relatively narrow diameter or slim well construction, which is typical for e.g. the Caspian Sea or the Gulf of Mexico, there is very little annular space between the outer casing string and the liner. It is typical that the outer casing string has an outer diameter (OD) of 16 inches (40.6 cm) and an internal diameter (ID) of 14.6 inches (37.1 cm) and the liner string has an OD of 14 inches (35.6 cm). The annular space between the outer casing string ID and the liner string OD of 0.3 inches (0.8 cm) is too small to fit a PBR or the expandable tieback connection of WO2011/048426 A2. We consider any wellbore where the annular space is too small to fit a standard PBR as a slim hole well.
Accordingly, an object of at least one embodiment of the present invention is to provide an expandable tieback connection suitable for use in a slim well construction.